1. Field of the Invention
This invention relates to oil well drilling and more particularly to sensor, telemetry and discrimination systems for detecting and indicating the presence downwell of particularly hazardous conditions and producing early warning to surface drill rig operators of the existence of such conditions.
2. Description of the Prior Art
For purposes of economics and safety during the drilling of oil wells, attempts, dating at least as far back as 1932, to make various measurements down well while drilling was taking place, have been made. The major obstacle to actual utilization of systems for this purpose has been the problem of transmitting values of parameters being measured deep in the earth, near the drill bits, back up to the drillers who could make strategic use of them to control the process.
In the 1960's and 1970's with the itensified need for "slant" or deviation drilling from a single central offshore platform, and the increasing awkwardness and cost in such wells of the frequent removal (tripping) of the drill string to permit measurement of various guiding parameters by lowering "wire-line" logs and sondes, measurement while drilling [MWD] was given new impetus which finally succeeded in launching the industrial development necessary to reduce this concept to actual large scale practice.
The first and seemingly logical attempts to transmit measured values up the steel drill pipes in the form of acoustical waves in the steel were doubly frustrated in that demands of the period were not only for increasing amounts of information (not only the original parameters such as compass heading of bore and angle from vertical but many new parameters as well), but also that more and more transmission horsepower was being required to overcome unexpectedly high sonic signal attenuation due to viscous damping by drilling mud and losses due to discontinuities in the drill string dimensions at collars and at threaded joints (joints occur at about 30 ft. intervals up drill strings that can be 15,000 to 20,000
The attempts to increase transmission signal horsepower and information density (number of parameters) resulted in abandonment of electric batteries as power sources by most aspiring MWD service firms, and the introduction of mud-flow driven turbine-generators down well to supply more power to transmission systems. At about the same time, several of the original developers gave up entirely on drill-string acoustical telemetry attempts and converted their (now mud-driven) power supply systems to the production of mud pressure signal pulses that travel at speeds of about 4000 ft/sec up the supply mud column which flows down through the center of the drill pipe. The early history of sonic and mud pulse system development is well related in the paper entitled "MUD PULSE LOGGING WHILE DRILLING TELEMETRY SYSTEM DESIGN, DEVELOPMENT, AND DEMONSTRATIONS", by R. F. Spinnler and F. A. Stone, presented at the 1978 Drilling Technology Conference of the International Association of Drilling Contractors Mar. 7-9, 1978, Houston, Tex. in which the authors relate their decision to convert from sonic to mud pulse telemetry regardless of limited data density in mud pulse systems, having been defeated by the high energy requirements (to overcome attenuation) in drill string source telemetry systems even though, conceptually, more data per second could have been transmitted via the steel pipe of the drill string.
Another paper entitled "MUD PULSE MWD (MEASUREMENT-WHILE-DRILLING) SYSTEMS REPORT", by M. Gearhart, A. Ziemer, and O. Knight, presented at the 56th Annual Fall Technical Conference and Exhibition of the of the Society of Petroleum Engineers of AIME, San Antonio, Tex., Oct. 5-7, 1981 describes state-of-the-art methods of mud pulse telemetry at that time including negative mud-pulse telemetry and positive and oscillating pressure pulses in the drill mud columns. At that time transmitting and receiving, just the six parameters that give complete drill direction data, took from 11/2 to 3 minutes of mud pressure pulsing by any of the operating mud pulse telemetry (MPT) systems.
A number of U.S. Pat. Nos. e.g., 4,302,826; 4,282,588; 4,390,975; 4,254,481; 4,298,970; 4,293,937; and 4,320,473 show continuation of the struggle to generate and maintain signals (deformation waves) in the steel drill pipes to utilize the conceptually advantageous, but apparently unattainable, advantages of the steel telemetry systems.
From the late 1970's to the present time the majority of development effort has concentrated on extending the range of parameters measured and transmitted from downwell during drilling from the original azimuth and angle measurements to include lithographic measurements such as formation gamma ray activity and resistivity and, later, a series of drilling parameter measurements such as weight and torque on bit, annular mud pressure and temperature and other bits of information, aimed at improving the economy of drilling and reducing frequency of expensive wire line logging which also interrupts costly drilling operations. All of this information availability has placed additional demand on the already limited data transmitting capability of mud pulse telemetry systems.
The U.S. Department of Interior sponsored, in an effort to improve offshore well safety, development work on faster mud pulse telemetry, based on the principles of fluidic amplifiers the results of which are reflected in the following U.S. Pat. Nos. 4,276,943; 4,291,395; 4,323,991; 4,391,299; and 4,418,721. The family of devices represented may represent the ultimate in rate of transmittal of information by MPT, having been tested at data rates up to 40 binary "bits" per second which (at 12 bits per data "word") is 40 to 80 times "faster" than mud pulse telemetry systems in current commercial use.
In their quest for information density in MWD, the telemetry developers have inadvertently neglected one of the vital potential roles for measurement while drilling, namely, the safety role of early notification to the drilling operator that an unsafe condition is occurring downwell.
The primary cause of drilling disasters is blow out which is preceeded by the phenomenon identified in the trade as a "kick" in which gas (or supersaturated hydrocarbon liquid) enters the mud filled drilling annulus unexpectedly and, in moving toward the upper (lower pressure) regions of the drill hole, expands and accelerates the displacement of mud from the annulus, leading, in the ultimate disaster, to uncontrolled burning of formation fluids and gases within the structure of the drilling rig. Only in about 1 well in 500 does such a blow-out occur, while a less serious "kick" that allows formation fluids to emerge from the annulus (and is controlled by means at hand) occurs once in four or five wells. A properly controlled drilling operation maintains mud pressure against the formation fluids throughout the drilling process and the gases and oils entering the mud are limited to those being liberated at the time by the bit from the rocks or formations currently being drilled.
When, on occasion, the formation pressures have been underestimated in control of drilling mud overpressure, or where pockets of gas or oil at unpredictedly high pressures are penetrated, formation fluids intrude into the drill annulus and an incipient "kick" condition exists. Such intrusions of formation fluids (which can be gas, gas saturated oils, or stable liquid hydrocarbons), are usually detected by mud flow and inventory instruments upwell and controlled by various techniques available to the driller, one of which is increasing mud density. Perhaps only one in twenty unexpected formation fluid intrusions actually develops in to a "kick", which is subsequently controlled by various means such as mud density change or even blow out preventers. Approximately one kick in one hundred develops into an uncontrolled blow out such as occurred in the Norwegian offshore fields on Oct. 6, 1985.
The unfortunate state-of-circumstances, in view of MWD development to date, is that 75% of such unplanned well fluid intrusions, with their associated small potential for disaster, occur at phases of the drilling cycle when all forms of mud pulse telemetry are inoperative because mud is not circulating. These phases of the cycle are conditions known, for example, as "tripping", when drill pipe is being removed for logging, "swabbing", when the suction of drill pipe being raised lowers mud pressures below the bit, and "hang off" when the drill pipe is left in the well (offshore) and the rig is moved away due to high seas, for example.
Thus, even if sensors had existed to reliably detect unexpected gas intrusion into the well, the chosen mud pulse (MPT) telemetry systems would not serve to alert the operator at an early stage of that occurrence in 75% of such potentially dangerous well fluid intrusions. Perhaps this unsuitability of MPT, the only practical telemetry to date, has implicitly discouraged effort directed specifically to the search for unambiguous detectors of the "kick alarm" condition itself, deep down well. "Alarm telemetry" does not yet exist because the high data density goals of "Information Telemetry", toward which developers have been striving, in themselves defeat the contrary criteria (not heretofore articulated) for "Alarm Telemetry" functions.
Information telemetry demands the nearly continuous flow of large numbers of data "bits" as rapidly as possible, and in so doing, has demanded that means be devised to supply growing amounts of energy on a more-or-less continuous basis.
In contrast, an alarm condition may occur as infrequently as once in two weeks or once in a month of drilling operations. Hence alarm telemetry requirements are not for streams of data "bits", to be detected and interpreted upwell, but rather for a transmitter-receiver system capable of unambiguously handling as few as four to six "bits" of transmitted data over a two month period. With such extremely low data density requirements defined and recognized, in contrast to high data density goals of information telemetry systems, such as 40 "bits" per second, entirely different boundary conditions exist that have enabled the inventor to fulfill the functional requirements of alarm telemetry. For example, it is possible to devote enormous energy to a single pulse, assuming the reliable transmission of a single "bit" of data indicating the binary statement "YES (an alarm condition does now exist)", whereas the continual expenditure of such energy on a stream of bits, as required for information telemetry, would require horsepower (or killowatt-hour) capacities beyond the reach of any mud turbogenerator or battery system conceivable for use downwell, and would exhaust single-use explosive cartridges at such rates as to render that means of energy delivery completely impracticable.